Apparatus and Method for Evaluating Cement Integrity in a Wellbore Using Acoustic Telemetry

ABSTRACT

An electro-acoustic system for downhole telemetry employs a series of communications nodes spaced along a string of casing within a wellbore. In one embodiment the nodes are placed within the cement sheath surrounding the joints of casing and allow wireless communication between transceivers residing within the communications nodes and a receiver at the surface. The transceivers provide node-to-node communication up a wellbore at high data transmission rates for data indicative of cement sheath integrity. A method of evaluating a cement sheath in a wellbore uses a plurality of data transmission nodes situated along the casing string which send signals to a receiver at the surface. The signals are then analyzed.

CROSS REFERENCE TO RELATED APPLICATIONS

This application claims the benefit of U.S. Provisional PatentApplication No. 61/739,681, filed Dec. 19, 2012, the disclosure of whichis hereby incorporated by reference.

BACKGROUND OF THE INVENTION

This section is intended to introduce various aspects of the art, whichmay be associated with exemplary embodiments of the present disclosure.This discussion is believed to assist in providing a framework tofacilitate a better understanding of particular aspects of the presentdisclosure. Accordingly, it should be understood that this sectionshould be read in this light, and not necessarily as admissions of priorart.

FIELD OF THE INVENTION

The present invention relates to the field of well drilling andcompletions. More specifically, the invention relates to thetransmission of data along a tubular body within a wellbore. The presentinvention further relates to the evaluation of cement integrity behind acasing string using acoustic signals.

GENERAL DISCUSSION OF TECHNOLOGY

In the drilling of oil and gas wells, a wellbore is formed using a drillbit that is urged downwardly at a lower end of a drill string. The drillbit is rotated while force is applied through the drill string andagainst the rock face of the formation being drilled. After drilling toa predetermined depth, the drill string and bit are removed and thewellbore is lined with a string of casing. An annular area is thusformed between the string of casing and the formation penetrated by thewellbore.

A cementing operation is typically conducted in order to displacedrilling fluid and fill part or all of the hollow-cylindrical annulararea between the casing and the borehole wall with cement. Thecombination of cement and casing strengthens the wellbore andfacilitates the zonal fluid isolation of certain sections of ahydrocarbon-producing formation (or “pay zones”) behind the casing.

A first string of casing is placed from the surface and down to a firstdrilled depth. This casing is known as a surface casing. In the case ofoffshore operations, this casing may be referred to as a conductor pipe.Typically, one of the main functions of the initial string(s) of casingis to isolate and protect the shallower, useable water bearing aquifersfrom contamination by any other wellbore fluids. Accordingly, thesecasing strings are almost always cemented entirely back to surface.

One or more intermediate strings of casing is also run into thewellbore. These casing strings will have progressively smaller outerdiameters into the wellbore. In most current wellbore completion jobs,especially those involving so called unconventional formations wherehigh-pressure hydraulic operations are conducted downhole, these casingstrings may be entirely cemented. In some instances, an intermediatecasing string may be a liner, that is, a string of casing that is nottied back to the surface.

The process of drilling and then cementing progressively smaller stringsof casing is repeated several times until the well has reached totaldepth. In some instances, the final string of casing is also a liner.The final string of casing, referred to as a production casing, is alsotypically cemented into place.

Additional tubular bodies may be included in a well completion. Theseinclude one or more strings of production tubing placed within theproduction casing or liner. Each tubing string extends from the surfaceto a designated depth proximate a production interval, or “pay zone.”Each tubing string may be attached to a packer. The packer serves toseal off the annular space between the production tubing string(s) andthe surrounding casing.

It is important that the cement sheath surrounding the casing stringshave a high degree of circumferential and axial integrity around thecasing annulus against fluid channeling or flowing through the cementalong the wellbore. The cement must also bond with the casing surfaceand borehole wall to affect a hydraulic seal against fluid migrationalong the wellbore. This means that the cement is fully placed into theannular region to prevent fluid communication between fluids at thelevel of subsurface completion and aquifers residing just below thesurface. Such fluids may include fracturing fluids, aqueous acid, andformation fluids.

Heretofore, the integrity of a cement sheath has been determined throughthe use of a so-called cement bond long. A cement bond log (or CBL),uses an acoustic signal that is transmitted by a logging tool at the endof a wireline. The logging tool includes a transmitter, and then areceiver that “listens” for sound waves generated by the transmitterthrough the surrounding case strings. The logging tool includes a signalprocessor that takes a continuous measurement of the amplitude of soundpulses from the transmitter to the receiver.

The theory behind the CBL is that the amplitude of a sonic signal as ittravels through a well cemented pipe is only a fraction of the amplitudethrough uncemented pipe. Acoustic signals in free steel casing generallyprovide a large amplitude because the acoustic energy remains in thesteel. However, for casing that is surrounded by and well bonded withcement, the amplitude is small because the acoustic energy is dispersednot only in the steel but also into the coupled cement and formation.Bond logs may also measure acoustic impedance of the cement or othermaterial in the annulus behind the casing by resonant frequency decay.

Cement bond logs are typically conducted using an acoustic logging toolthat is pulled through the wellbore using a wireline. This is done aftera casing string has been cemented in placed within the wellbore.However, it is desirable to be able to evaluate the integrity of thecement sheath behind the casing string immediately after the cementingoperation has been conducted and without need for a wireline or separatelogging tool. Further, it is desirable to determine the progress ofcement placement during the cementing operation using a series ofcommunications nodes placed along the casing string as part of the wellcompletion. Still further, a need exists for an acoustic telemetrysystem that enables the operator to receive signals at high datatransmission rates, with such signals being indicative of cement sheathintegrity, both at the time of cementing and later in the life of thewell.

SUMMARY OF THE INVENTION

An electro-acoustic system for downhole telemetry is provided herein.The system employs a series of communications nodes spaced along awellbore. Each node transmits a signal that represents a packet ofinformation. The packet of information includes both a node identifierand an acoustic wave. The signals are relayed up the wellbore fromnode-to-node in order to provide a wireless signal to a receiver at thesurface.

The system first includes a string of casing. The casing string isdisposed in the wellbore. In actuality, the wellbore may have more thanone casing string, including a string of surface casing, one or moreintermediate casing strings, and a production casing. In any aspect, thewellbore is completed for the purpose of conducting hydrocarbon recoveryoperations. A cement sheath resides within an annular region formedbetween the casing string and a surrounding subsurface rock matrix. Thecement sheath extends substantially along the exterior of the casingstring.

The system further has a topside communications node. The topsidecommunications node may be placed along the casing string proximate tosurface. The surface may be an earth surface. Alternatively, in a subseacontext, the surface may be an offshore platform or vessel at or below awater level. In another embodiment, the topside communications node isconnected to the wellhead.

The system further includes a plurality of subsurface communicationsnodes. The subsurface communications nodes are attached to an outer wallof the casing string in spaced-apart relation. In one aspect, thecommunications nodes are spaced at between about 20 and 40 foot (6.1 to12.2 meter) intervals. Preferably, each joint of pipe making up thecasing string receives one node. The communications nodes are configuredto transmit acoustic waves from node-to-node, up to the topsidecommunications node.

Each of the subsurface communications nodes has a sealed housing. Inaddition, each node relies upon an independent power source. The powersource may be, for example, batteries or a fuel cell. The power sourceresides within the housing.

In addition, each of the subsurface communications nodes has anelectro-acoustic transducer. In one aspect, the communications nodestransmit data as mechanical waves at a rate exceeding about 50 bps. Inone aspect, the electro-acoustic transducer is associated with atransceiver designed to receive acoustic waves at a first frequency, andthen transmit or relay the acoustic waves at a second differentfrequency. Multiple frequency shift keying (MFSK) may be used as amodulation scheme enabling the transmission of information.

The system also includes a receiver. The receiver is positioned at thesurface and is configured to receive signals from the topsidecommunications node. The signals originate with the various subsurfacecommunications nodes. In one aspect, the receiver is in electricalcommunication with the topside communications node by means of anelectrical wire or through a wireless data transmission such as Wi-Fi orBlue Tooth. The receiver is configured to process the signals toidentify any sections of casing that are not adequately cemented.

A method of detecting the integrity of a cement sheath along a wellboreis also provided herein. The method uses a plurality of datatransmission nodes situated along a casing string to accomplish awireless transmission of data along the wellbore. The data representssignals that indicate the presence of a cement sheath both adjacent toand between the respective communications nodes.

The method first includes running joints of pipe into the wellbore. Thejoints of pipe are connected together at threaded couplings. The jointsof pipe are fabricated from a steel material and have a resonantfrequency.

The method also provides for attaching a series of communications nodesto the joints of pipe according to a pre-designated spacing. In oneaspect, each joint of pipe receives at least one communications node.Preferably, each of the communications nodes is attached to a joint ofpipe by one or more clamps. In this instance, the step of attaching thecommunications nodes to the joints of pipe comprises clamping thecommunications nodes to an outer surface of the joints of pipe.

The series of communications nodes includes a topside communicationsnode. This is the uppermost communications node along the wellbore. Morespecifically, the topside communications node is attached to the tubularbody proximate the surface. Alternatively, the topside communicationsnode is connected to the well head or to a tubular body immediatelydownstream from the wellhead. The topside communications node transmitssignals from an uppermost subsurface communications node to the surface.

The communications nodes also include a series of subsurfacecommunications nodes residing below the topside communications nodes.The subsurface communications nodes reside in spaced-apart relationalong the casing string. The subsurface communications nodes areconfigured to transmit acoustic waves up to the topside communicationsnode. Each subsurface communications node includes an electro-acoustictransducer and associated transceiver that receives an acoustic signalfrom a previous communications node, and then transmits or relays thatacoustic signal to a next communications node, in node-to-nodearrangement. In one aspect, the communications nodes transmit data asmechanical waves at a rate exceeding about 50 bps.

In one embodiment, one or more of the subsurface communications nodesincludes a temperature sensor. The communications nodes are thendesigned to generate a signal that corresponds to temperature readingssensed by the respective temperature sensors. The electro-acoustictransceivers in the subsurface communications nodes then transmitacoustic signals up the wellbore representative of the temperaturereadings, node-to-node.

In another embodiment, selected subsurface communications nodes includea strain gauge. Alternatively or in addition, selected subsurfacecommunications nodes include passive acoustic sensors, or microphones.Signals from the strain gauges or the microphones are sent to thesurface via the subsurface communications nodes.

The method next includes providing a receiver. The receiver is placed atthe surface. The receiver has a processor that processes signalsreceived from the topside communications node, such as through the useof firmware and/or software. The receiver preferably receives electricalor optical signals via a so-called “Class I, Division I” conduit,meaning a conduit (as defined by NFPA 497 and API 500) for operation inan electrically classified area. Alternatively, data may be transferredfrom the topside communications node to the receiver via anelectromagnetic (RF) wireless connection. The processor processes thesignals to identify which signals correlate to which subsurfacecommunications node.

The method also includes analyzing the signals to evaluate the integrityof the cement sheath in proximity to each of the communications nodes.Analyzing the signals will allow the operator to infer the quality ofthe cement sheath at and in between the nodes. If it is determined thatcement has not been properly placed around the casing string adjacentone of the communications nodes, then appropriate decisions onsubsequent drilling, completing, operating or abandonment the well canbe undertaken.

BRIEF DESCRIPTION OF THE DRAWINGS

So that the present inventions can be better understood, certaindrawings, charts, graphs and/or flow charts are appended hereto. It isto be noted, however, that the drawings illustrate only selectedembodiments of the inventions and are therefore not to be consideredlimiting of scope, for the inventions may admit to other equallyeffective embodiments and applications.

FIG. 1 is a side, cross-sectional view of an illustrative wellbore. Thewellbore is being formed using a derrick, a drill string and a bottomhole assembly. A series of communications nodes is placed along thedrill string as part of a telemetry system.

FIG. 2 is a cross-sectional view of a wellbore having been completed.The illustrative wellbore has been completed as a cased hole completion.A series of communications nodes is placed along the casing string aspart of a telemetry system.

FIG. 3 is a perspective view of an illustrative tubular pipe joint asmay be positioned in a wellbore. A communications node of the presentinvention, in one embodiment, is shown exploded away from the pipejoint.

FIG. 4A is a perspective view of a communications node as may be used inthe wireless data transmission system of the present invention, in analternate embodiment.

FIG. 4B is a cross-sectional view of the communications node of FIG. 4A.The view is taken along the longitudinal axis of the node. Here, asensor is provided within the communications node.

FIG. 4C is another cross-sectional view of the communications node ofFIG. 4A. The view is again taken along the longitudinal axis of thenode. Here, a sensor resides along the wellbore external to thecommunications node.

FIGS. 5A and 5B are perspective views of a shoe as may be used onopposing ends of the communications node of FIG. 4A, in one embodiment.In FIG. 5A, the leading edge, or front, of the shoe is seen. In FIG. 5B,the back of the shoe is seen.

FIG. 6 is a perspective view of a communications node system as may beused in the methods of the present invention, in one embodiment. Thecommunications node system utilizes a pair of clamps for connecting asubsurface communications node onto a tubular body.

FIG. 7 is a flowchart demonstrating steps of a method for detecting theintegrity of a cement sheath along a wellbore in accordance with thepresent inventions, in one embodiment.

DETAILED DESCRIPTION OF CERTAIN EMBODIMENTS Definitions

As used herein, the term “hydrocarbon” refers to an organic compoundthat includes primarily, if not exclusively, the elements hydrogen andcarbon. Examples of hydrocarbons include any form of natural gas, oil,coal, and bitumen that can be used as a fuel or upgraded into a fuel.

As used herein, the term “hydrocarbon fluids” refers to a hydrocarbon ormixtures of hydrocarbons that are gases or liquids. For example,hydrocarbon fluids may include a hydrocarbon or mixtures of hydrocarbonsthat are gases or liquids at formation conditions, at processingconditions, or at ambient conditions (about 20° C. and 1 atm pressure).Hydrocarbon fluids may include, for example, oil, natural gas, gascondensates, coal bed methane, shale oil, pyrolysis oil, and otherhydrocarbons that are in a gaseous or liquid state.

As used herein, the term “subsurface” refers to the region below theearth's surface.

As used herein, the term “sensor” includes any electrical sensing deviceor gauge. The sensor may be capable of monitoring or detecting pressure,temperature, fluid flow, vibration, or resistivity or other formationdata.

As used herein, the term “formation” refers to any definable subsurfaceregion. The formation may contain one or more hydrocarbon-containinglayers, one or more non-hydrocarbon containing layers, an overburden,and/or an underburden of any geologic formation.

The terms “zone” or “zone of interest” refer to a portion of a formationcontaining hydrocarbons. The term “hydrocarbon-bearing formation” mayalternatively be used. Zones of interest may also include formationscontaining brines or useable water which are to be isolated.

As used herein, the term “wellbore” refers to a hole in the subsurfacemade by drilling or insertion of a conduit into the subsurface. Awellbore may have a substantially circular cross section, or othercross-sectional shape. As used herein, the term “well,” when referringto an opening in the formation, may be used interchangeably with theterm “wellbore.”

The terms “tubular member” or “tubular body” refer to any pipe, such asa joint or string of casing, a joint or string of a liner pipe, a jointor string of drill pipe, a production tubing joint or string, aninjection tubing joint or string, or any other tubular tool associatedwith use in a wellbore.

DESCRIPTION OF SELECTED SPECIFIC EMBODIMENTS

The inventions are described herein in connection with certain specificembodiments. However, to the extent that the following detaileddescription is specific to a particular embodiment or a particular use,such is intended to be illustrative only and is not to be construed aslimiting the scope of the inventions.

FIG. 1 is a side, cross-sectional view of an illustrative well site 100.The well site 100 includes a derrick 120 at an earth surface 101. Thewell site 100 also includes a wellbore 150 extending from the earthsurface 101 and down into an earth subsurface 155. The wellbore 150 isbeing formed using the derrick 120, a drill string 160 below the derrick120, and a bottom hole assembly 170 at a lower end of the drill string160.

Referring first to the derrick 120, the derrick 120 includes a framestructure 121 that extends up from the earth surface 101. The derrick120 supports drilling equipment including a traveling block 122, a crownblock 123 and a swivel 124. A so-called kelly 125 is attached to theswivel 124. The kelly 125 has a longitudinally extending bore (notshown) in fluid communication with a kelly hose 126. The kelly hose 126,also known as a mud hose, is a flexible, steel-reinforced, high-pressurehose that delivers drilling fluid through the bore of the kelly 125 anddown into the drill string 160.

The kelly 125 includes a drive section 127. The drive section 127 isnon-circular in cross-section and conforms to an opening 128longitudinally extending through a kelly drive bushing 129. The kellydrive bushing 129 is part of a rotary table. The rotary table is amechanically driven device that provides clockwise (as viewed fromabove) rotational force to the kelly 125 and connected drill string 160to facilitate the process of drilling a borehole 105. Both linear androtational movement may thus be imparted from the kelly 125 to the drillstring 160.

A platform 102 is provided for the derrick 120. The platform 102 extendsabove the earth surface 101. The platform 102 generally supports righands along with various components of drilling equipment such as apumps, motors, gauges, a dope bucket, tongs, pipe lifting equipment andcontrol equipment. The platform 102 also supports the rotary table.

It is understood that the platform 102 shown in FIG. 1 is somewhatschematic. It is also understood that the platform 102 is merelyillustrative and that many designs for drilling rigs and platforms, bothfor onshore and for offshore operations, exist. These include, forexample, top drive drilling systems. The claims provided herein are notlimited by the configuration and features of the drilling rig unlessexpressly stated in the claims.

Placed below the platform 102 and the kelly drive section 127 but abovethe earth surface 101 is a blow-out preventer, or BOP 130. The BOP 130is a large, specialized valve or set of valves used to control pressuresduring the drilling of oil and gas wells. Specifically, blowoutpreventers control the fluctuating pressures emanating from subterraneanformations during a drilling process. The BOP 130 may include upper 132and lower 134 rams used to isolate flow on the back side of the drillstring 160. Blowout preventers 130 also prevent the pipe joints makingup the drill string 160 and the drilling fluid from being blown out ofthe wellbore 150 in the event of a sudden pressure kick.

As shown in FIG. 1, the wellbore 150 is being formed down into thesubsurface formation 155. In addition, the wellbore 150 is being shownas a deviated wellbore. Of course, this is merely illustrative as thewellbore 150 may be a vertical well or even a horizontal well, as shownlater in FIG. 2.

In drilling the wellbore 150, a first string of casing 110 is placeddown from the surface 101. This is known as surface casing 110 or, insome instances (particularly offshore), conductor pipe. The surfacecasing 110 is secured within the formation 155 by a cement sheath 112.The cement sheath 112 resides within an annular region 115 between thesurface casing 110 and the surrounding formation 155.

During the process of drilling and completing the wellbore 150,additional strings of casing (not shown) will be provided. These mayinclude intermediate casing strings and a final production casingstring. For an intermediate case string or the final production casing,a liner may be employed, that is, a string of casing that is not tiedback to the surface 101.

As noted, the wellbore 150 is formed by using a bottom hole assembly170. The bottom-hole assembly 170 allows the operator to control or“steer” the direction or orientation of the wellbore 150 as it isformed. In this instance, the bottom hole assembly 170 is known as arotary steerable drilling system, or RSS.

The bottom hole assembly 170 will include a drill bit 172. The drill bit172 may be turned by rotating the drill string 160 from the platform102. Alternatively, the drill bit 172 may be turned by using so-calledmud motors 174. The mud motors 174 are mechanically coupled to and turnthe nearby drill bit 172. The mud motors 174 are used with stabilizersor bent subs 176 to impart an angular deviation to the drill bit 172.This, in turn, deviates the well from its previous path in the desiredazimuth and inclination.

There are several advantages to directional drilling. These primarilyinclude the ability to complete a wellbore along a substantiallyhorizontal axis of a subsurface formation, thereby exposing a greaterformation face. These also include the ability to penetrate intosubsurface formations that are not located directly below the wellhead.This is particularly beneficial where an oil reservoir is located underan urban area or under a large body of water. Another benefit ofdirectional drilling is the ability to group multiple wellheads on asingle platform, such as for offshore drilling. Finally, directionaldrilling enables multiple laterals and/or sidetracks to be drilled froma single wellbore in order to maximize reservoir exposure and recoveryof hydrocarbons.

As the wellbore 150 is being formed, the operator may wish to evaluatethe integrity of the cement sheath 112 placed around the surface casing110 (or other casing string). To do this, the industry has relied uponso-called cement bond logs. As discussed above, a cement bond log (orCBL), uses an acoustic signal that is transmitted by a logging tool atthe end of a wireline. The logging tool includes a transmitter, and oneor more receivers that “listen” for sound waves generated by thetransmitter through the surrounding casing string. The logging toolincludes a signal processor that takes a continuous measurement of theamplitude of sound pulses from the transmitter to the receiver.Alternately, the attenuation of the sonic signal may be measured.

In some instances, a bond log will measure acoustic impedance of thematerial in the annulus directly behind the casing. This may be donethrough resonant frequency decay. Such logs include, for example, theUSIT log of Schlumberger (of Sugar Land, Tex.) and the CAST-V log ofHalliburton (of Houston, Tex.).

It is desirable to implement a downhole telemetry system that enablesthe operator to evaluate cement sheath integrity without need of runninga CBL line. This enables the operator to check cement sheath integrityas soon as the cement has set in the annular region 115 or as soon asthe wellbore 150 is completed. To do this, the well site 100 includes aplurality of communications nodes 180, 182. The communications nodes180, 182 are placed along the outer surface of the surface casing 110according to a pre-designated spacing. The communications nodes thensend acoustic signals up the wellbore 150 in node-to-node arrangement.

Acoustic telemetry systems are known in the industry. U.S. Pat. No.5,924,499 entitled “Acoustic Data Link and Formation Property Sensor forDownhole MWD System” teaches the use of acoustic signals for “shorthopping” a component along a drill string. Signals are transmitted fromthe drill bit or from a near-bit sub and across the mud motors. This maybe done by sending separate acoustic signals simultaneously—one that issent through the drill string, a second that is sent through thedrilling mud, and optionally, a third that is sent through theformation. These signals are then processed to extract readable signals.

U.S. Pat. No. 6,912,177, entitled “Transmission of Data in Boreholes,”addresses the use of an acoustic transmitter that is as part of adownhole tool. Here, the transmitter is provided adjacent a downholeobstruction such as a shut-in valve along a drill stem so that anelectrical signal may be sent across the drill stem. U.S. Pat. No.6,899,178, entitled “Method and System for Wireless Communications forDownhole Applications,” describes the use of a “wireless tooltransceiver” that utilizes acoustic signaling. Here, an acoustictransceiver is in a dedicated tubular body that is integral with a gaugeand/or sensor. This is described as part of a well completion.

U.S. Pat. No. 4,314,365, entitled “Acoustic Transmitter and Method toProduce Essentially Longitudinal, Acoustic Waves, teaches a “portable,electrohydraulic, acoustic transmitter” that attaches to an outersurface of a drill string. The transmitter is used to send acousticsignals down a drill string to a downhole receiver. When actuated, thedownhole receiver activates a subsurface “instrument package” whichperforms a desired “downhole function.”

None of these patents disclose an acoustic telemetry system that enablesan operator to receive signals at the surface that are indicative ofcement sheath integrity behind a casing string. In contrast, the wellsite 100 of FIG. 1 presents a telemetry system that utilizes a series ofnovel communications nodes 180, 182 placed along the casing 110. Thesenodes 180, 182 allow for the high speed transmission of wireless signalsbased on the in situ generation of acoustic waves. The waves representwave forms that may be processed and analyzed at the surface.

The nodes first include a topside communications node 182. The topsidecommunications node 182 is placed closest to the surface 101. Thetopside communications node 182 is configured to receive acousticsignals and convert them to electrical or optical signals. The topsidecommunications node 182 may be above grade or below grade.

In addition, the nodes include a plurality of subsurface communicationsnodes 180. The subsurface communications nodes 180 are configured toreceive and then relay acoustic signals along the length of the wellbore150 up to the topside communications node 182.

In FIG. 1, the nodes 180, 182 are shown schematically. However, FIG. 3offers an enlarged perspective view of an illustrative pipe joint 300,along with a communications node 350. The illustrative communicationsnode 350 is shown exploded away from the pipe joint 300.

In FIG. 3, the pipe joint 300 is intended to represent a joint ofcasing. However, the pipe joint 300 may be any other tubular body suchas a joint of tubing, drill pipe, pipeline, or other jointed tubularconduit assembly. The illustrated pipe joint 300 has an elongated wall310 defining an internal bore 315. The bore 315 transmits drillingfluids such as an oil based mud, or OBM, during a drilling operation.The bore 315 also receives a string of tubing (such as production tubingor injection tubing, not shown), once a wellbore is completed.

The illustrated pipe joint 300 has a box end 322 having internalthreads. In addition, the pipe joint 300 has a pin end 324 havingexternal threads, such as via an integrated box end or with aninternally threaded collar connector. The threads may be of any design.Tubing joints and casing joints have a slightly different general endappearance than the illustrated drill pipe joint, but these are alsotubular bodies that may be equipped similar to the illustrated drillpipe joint 300.

As noted, an illustrative communications node 350 is shown exploded awayfrom the pipe joint 300. The communications node 350 is designed toattach to the wall 410 of the pipe joint 300 at a selected location. Inone aspect, each pipe joint 300 will have a communications node 350between the box end 322 and the pin end 324. In one arrangement, thecommunications node 350 is placed immediately adjacent the box end 322or, alternatively, immediately adjacent the pin end 324 of every jointof pipe. In another arrangement, the communications node 350 is placedat a selected location along every second or every third pipe joint 300in a drill string. In still another arrangement, at least some pipejoints 300 receive two communications nodes 350.

The communications node 350 shown in FIG. 3 is designed to be pre-weldedonto the wall 310 of the pipe joint 300. Alternatively, thecommunications node 350 may be glued using an adhesive such as epoxy.However, it is preferred that the communications node 350 be configuredto be selectively attachable to/detachable from a pipe joint 300 bymechanical means at a well site. This may be done, for example, throughthe use of clamps. Such a clamping system is shown at 600 in FIG. 6,described more fully below. In any instance, the communications node 350is an independent wireless communications device that is designed to beattached to an external surface of a well pipe.

There are benefits to the use of an externally-placed communicationsnode that uses acoustic waves. For example, such a node will notdecrease the effective inner diameter which would interfere with passingsubsequent assemblies or tubulars through the internal bore 315 of thepipe joint 300. Further, installation and mechanical attachment can bereadily assessed and adjusted.

In FIG. 3, the communications node 350 includes an elongated body 351.The body 351 supports one or more batteries, shown schematically at 352.The body 351 also supports an electro-acoustic transducer, shownschematically at 354. The electro-acoustic transducer 354 is associatedwith a transceiver that receives acoustic signals at a first frequency,converts the received signals into a digital signal, converts thedigital signal back into an acoustic signal, and transmits the acousticsignal at a second different frequency to a next communications node.

The communications node 350 is intended to represent the communicationsnodes 180 of FIG. 1, in one embodiment. The electro-acoustic transducer354 in each node 180 allows signals to be sent from node-to-node, up thewellbore 150, as acoustic waves. The acoustic waves may be at afrequency of, for example, between about 100 kHz and 125 kHz. A lastsubsurface communications node 180 transmits the signals to the topsidenode 182. Beneficially, the subsurface communications nodes 180 do notrequire a wire or cable to transmit data to the surface. Preferably,communication is routed around nodes which are not functioning properly.

The well site 100 of FIG. 1 also shows a receiver 190. The receiver 190comprises a processor 192 that receives signals sent from the topsidecommunications node 182. The signals may be received through a wire (notshown) such as a co-axial cable, a fiber optic cable, a USB cable, orother electrical or optical communications wire. Alternatively, thereceiver 190 may receive the final signals from the topside node 182wirelessly through a modem, a transceiver or other wirelesscommunications link such as Bluetooth or Wi-Fi. The receiver 190preferably receives electrical signals via a so-called Class I, DivisionI conduit, that is, a housing for wiring that is considered acceptablysafe in an explosive environment. In some applications, radio, infraredor microwave signals may be utilized.

The processor 192 may include discrete logic, any of various integratedcircuit logic types, or a microprocessor. In any event, the processor192 may be incorporated into a computer having a screen. The computermay have a separate keyboard 194, as is typical for a desk-top computer,or an integral keyboard as is typical for a laptop or a personal digitalassistant. In one aspect, the processor 192 is part of a multi-purpose“smart phone” having specific “apps” and wireless connectivity.

FIG. 1 demonstrates the use of a wireless data telemetry system during adrilling operation. However, the wireless downhole telemetry system mayalso be employed after a well is completed. This enables the operator toconfirm the viability of a cement sheath after, for example, formationfracturing operations have taken place.

FIG. 2 is a cross-sectional view of an illustrative well site 200. Thewell site 200 includes a wellbore 250 that penetrates into a subsurfaceformation 255. The wellbore 250 has been completed as a cased-holecompletion for producing hydrocarbon fluids. The well site 200 alsoincludes a well head 260. The well head 260 is positioned at an earthsurface 201 to control and direct the flow of formation fluids from thesubsurface formation 255 to the surface 201.

Referring first to the well head 260, the well head 260 may be anyarrangement of pipes or valves that receive reservoir fluids at the topof the well. In the arrangement of FIG. 2, the well head 260 representsa so-called Christmas tree. A Christmas tree is typically used when thesubsurface formation 255 has enough in situ pressure to drive productionfluids from the formation 255, up the wellbore 250, and to the surface201. The illustrative well head 260 includes a top valve 262 and abottom valve 264.

It is understood that rather than using a Christmas tree, the well head260 may alternatively include a motor (or prime mover) at the surface201 that drives a pump. The pump, in turn, reciprocates a set of suckerrods and a connected positive displacement pump (not shown) downhole.The pump may be, for example, a rocking beam unit or a hydraulic pistonpumping unit. Alternatively still, the well head 260 may be configuredto support a string of production tubing having a downhole electricsubmersible pump, a gas lift valve, or other means of artificial lift(not shown). The present inventions are not limited by the configurationof operating equipment at the surface unless expressly noted in theclaims.

Referring next to the wellbore 250, the wellbore 250 has been completedwith a series of pipe strings referred to as casing. First, a string ofsurface casing 210 has been cemented into the formation. Cement is shownin an annular bore 215 of the wellbore 250 around the casing 210. Thecement is in the form of an annular sheath 212. The surface casing 110has an upper end in sealed connection with the lower valve 264.

Next, at least one intermediate string of casing 220 is cemented intothe wellbore 250. The intermediate string of casing 220 is in sealedfluid communication with the upper master valve 262. A cement sheath 212is again shown in a bore 215 of the wellbore 250. The combination of thecasing 210/220 and the cement sheath 212 in the bore 215 strengthens thewellbore 250 and facilitates the isolation of formations behind thecasing 210/220.

It is understood that a wellbore 250 may, and typically will, includemore than one string of intermediate casing. In some instances, anintermediate string of casing may be a liner.

Finally, a production string 230 is provided. The production string 230is hung from the intermediate casing string 230 using a liner hanger231. The production string 230 is a liner that is not tied back to thesurface 101. In the arrangement of FIG. 2, a cement sheath 232 isprovided around the liner 230.

The production liner 230 has a lower end 234 that extends to an end 254of the wellbore 250. For this reason, the wellbore 250 is said to becompleted as a cased-hole well. Those of ordinary skill in the art willunderstand that for production purposes, the liner 230 may be perforatedafter cementing to create fluid communication between a bore 235 of theliner 230 and the surrounding rock matrix making up the subsurfaceformation 255. In one aspect, the production string 230 is not a linerbut is a casing string that extends back to the surface.

As an alternative, end 254 of the wellbore 250 may include joints ofsand screen (not shown). The use of sand screens with gravel packsallows for greater fluid communication between the bore 235 of the liner230 and the surrounding rock matrix while still providing support forthe wellbore 250. In this instance, the wellbore 250 would include aslotted base pipe as part of the sand screen joints. Of course, the sandscreen joints would not be cemented into place and would not includesubsurface communications nodes.

The wellbore 250 optionally also includes a string of production tubing240. The production tubing 240 extends from the well head 260 down tothe subsurface formation 255. In the arrangement of FIG. 2, theproduction tubing 240 terminates proximate an upper end of thesubsurface formation 255. A production packer 241 is provided at a lowerend of the production tubing 240 to seal off an annular region 245between the tubing 240 and the surrounding production liner 230.However, the production tubing 240 may extend closer to the end 234 ofthe liner 230.

In some completions a production tubing 240 is not employed. This mayoccur, for example, when a monobore is in place.

It is also noted that the bottom end 234 of the production string 230 iscompleted substantially horizontally within the subsurface formation255. This is a common orientation for wells that are completed inso-called “tight” or “unconventional” formations. Horizontal completionsnot only dramatically increase exposure of the wellbore to the producingrock face, but also enables the operator to create fractures that aresubstantially transverse to the direction of the wellbore. Those ofordinary skill in the art may understand that a rock matrix willgenerally “part” in a direction that is perpendicular to the directionof least principal stress. For deeper wells, that direction is typicallysubstantially vertical. However, the present inventions have equalutility in vertically completed wells or in multi-lateral deviatedwells.

As with the well site 100 of FIG. 1, the well site 200 of FIG. 2includes a telemetry system that utilizes a series of novelcommunications nodes. This again is for the purpose of evaluating theintegrity of the cement sheath 212, 232. The communications nodes areplaced along the outer diameter of the casing strings 210, 220, 230.These nodes allow for the high speed transmission of wireless signalsbased on the in situ generation of acoustic waves.

The nodes first include a topside communications node 282. The topsidecommunications node 282 is placed closest to the surface 201. Thetopside node 282 is configured to receive acoustic signals.

In addition, the nodes include a plurality of subsurface communicationsnodes 280. Each of the subsurface communications nodes 280 is configuredto receive and then relay acoustic signals along essentially the lengthof the wellbore 250. Preferably, the subsurface communications nodes 280utilize two-way electro-acoustic transducers to receive and relaymechanical waves.

The subsurface communications nodes 280 transmit signals as acousticwaves. The acoustic waves are preferably at a frequency of between about50 kHz and 500 kHz. The signals are delivered up to the topsidecommunications node 282 so that signals indicative of cement integrityare sent from node-to-node. A last subsurface communications node 280transmits the signals acoustically to the topside communications node282. Communication may be between adjacent nodes or may skip nodesdepending on node spacing or communication range. Preferably,communication is routed around nodes which are not functioning properly.

The well site 200 of FIG. 2 shows a receiver 270. The receiver 270comprises a processor 272 that receives signals sent from the topsidecommunications node 284. The processor 272 may include discrete logic,any of various integrated circuit logic types, or a microprocessor. Thereceiver 270 may include a screen and a keyboard 274 (either as a keypador as part of a touch screen). The receiver 270 may also be an embeddedcontroller with neither a screen nor a keyboard which communicates witha remote computer such as via wireless, cellular modem, or telephonelines.

The signals may be received by the processor 272 through a wire (notshown) such as a co-axial cable, a fiber optic cable, a USB cable, orother electrical or optical communications wire. Alternatively, thereceiver 270 may receive the final signals from the topside node 282wirelessly through a modem or transceiver. The receiver 270 preferablyreceives electrical signals via a so-called Class I, Div. 1 conduit,that is, a wiring system or circuitry that is considered acceptably safein an explosive environment.

FIGS. 1 and 2 present illustrative wellbores 150, 250 that may receive adownhole telemetry system using acoustic transducers. In each of FIGS. 1and 2, the top of the drawing page is intended to be toward the surfaceand the bottom of the drawing page toward the well bottom. While wellscommonly are completed in substantially vertical orientation, it isunderstood that wells may also be inclined and even horizontallycompleted. When the descriptive terms “up” and “down” or “upper” and“lower” or similar terms are used in reference to a drawing, they areintended to indicate location on the drawing page, and not necessarilyorientation in the ground, as the present inventions have utility nomatter how the wellbore is orientated.

In each of FIGS. 1 and 2, the communications nodes 180, 280 arespecially designed to withstand the same corrosion and environmentalconditions (high temperature, high pressure) of a wellbore 150 or 250 Asthe casing, drill string, or production tubing. To do so, it ispreferred that the communications nodes 180, 280 include steel housingsfor holding the electronics. In one aspect, the steel material is acorrosion resistant alloy.

FIG. 4A is a perspective view of a communications node 400 as may beused in the wireless data transmission systems of FIG. 1 or FIG. 2 (orother wellbore), in one embodiment. The communications node 400 isdesigned to provide data communication using a transceiver within anovel downhole housing assembly. FIG. 4B is a cross-sectional view ofthe communications node 400 of FIG. 4A. The view is taken along thelongitudinal axis of the node 400. The communications node 400 will bediscussed with reference to FIGS. 4A and 4B, together.

The communications node 400 first includes a fluid-sealed housing 410.The housing 410 is designed to be attached to an outer wall of a jointof wellbore pipe, such as the pipe joint 300 of FIG. 3. Where thewellbore pipe is a carbon steel pipe joint such as drill pipe, casing orliner, the housing 410 is preferably fabricated from carbon steel. Thismetallurgical match avoids galvanic corrosion at the coupling.

The housing 410 includes an outer wall 412. The wall 412 is dimensionedto protect internal electronics for the communications node 400 fromwellbore fluids and pressure. In one aspect, the wall 412 is about 0.2inches (0.51 cm) in thickness. The housing 410 optionally also has aprotective outer layer 425. The protective outer layer 425 residesexternal to the wall 412 and provides an additional thin layer ofprotection for the electronics.

A bore 405 is formed within the wall 412. The bore 405 houses theelectronics, shown in FIG. 4B as a battery 430, a power supply wire 435,a transceiver 440, and a circuit board 445. The circuit board 445 willpreferably include a micro-processor or electronics module thatprocesses acoustic signals. An electro-acoustic transducer 442 isprovided to convert acoustical energy to electrical energy (orvice-versa) and is coupled with outer wall 412 on the side attached tothe tubular body. The transducer 442 is in electrical communication witha sensor 432.

It is noted that in FIG. 4B, the sensor 432 resides within the housing410 of the communications node 400. However, as noted, the sensor 432may reside external to the communications node 400, such as above orbelow the node 400 along the wellbore. In FIG. 4C, a dashed line isprovided showing an extended connection between the sensor 432 and theelectro-acoustic transducer 442.

The transceiver 440 will receive an acoustic telemetry signal. In onepreferred embodiment, the acoustic telemetry data transfer isaccomplished using multiple frequency shift keying (MFSK). Anyextraneous noise in the signal is moderated by using well-knownconventional analog and/or digital signal processing methods. This noiseremoval and signal enhancement may involve conveying the acoustic signalthrough a signal conditioning circuit using, for example, a bandpassfilter.

The transceiver will also produce acoustic telemetry signals. In onepreferred embodiment, an electrical signal is delivered to anelectromechanical transducer, such as through a driver circuit. In apreferred embodiment, the transducer is the same electro-acoustictransducer that originally received the MFSK data. The signal generatedby the electro-acoustic transducer then passes through the housing 410to the tubular body (such as production tubing 240), and propagatesalong the tubular body to other communication nodes. The re-transmittedsignal represents the same sensor data originally transmitted by sensorcommunications node 284. In one aspect, the acoustic signal is generatedand received by a magnetostrictive transducer comprising a coil wrappedaround a core as the transceiver. In another aspect, the acoustic signalis generated and received by a piezoelectric ceramic transducer. Ineither case, the electrically encoded data are transformed into a sonicwave that is carried through the wall of the tubular body in thewellbore.

Each transceiver 440 is associated with a specific joint of pipe. Thatjoint of pipe, in turn, has a known location or depth along thewellbore. The acoustic wave as originally transmitted from thetransceiver 440 will represent a packet of information. The packet willinclude an identification code that tells a receiver (such as receiver270 in FIG. 2) where the signal originated, that is, whichcommunications node 400 it came from. In addition, the packet willinclude an amplitude value originally recorded by the communicationsnode 400 for its associated joint of pipe.

When the signal reaches the receiver at the surface, the signal isprocessed. This involves identifying which communications node thesignal originated from, and then determining the location of thatcommunications node along the wellbore. This further involves comparingthe original amplitude value with a baseline value. The baseline valuerepresents an anticipated value for a joint of casing having a fluidresiding within its bore and a continuous cement sheath along its outersurface.

If the measured amplitude value is at or below the baseline amplitudevalue, then the operator can assume that a cement sheath has been placedaround the joint of pipe at issue. On the other hand, if the measuredamplitude value is above the baseline amplitude value, then the operatorshould assume that a poor cement sheath has been placed around the jointof pipe at issue. In that instance, remedial steps may be taken. Wherethe wellbore is presently undergoing a cementing operation, such stepsmay include further injecting cement through a cement shoe and up theannular region in the hopes of filling the annular region. More likely,where the wellbore has been completed, such steps may include placingperforations in the casing at the subject joint of pipe, and thenconducting a so-called “cement squeeze” in order to isolate the joint ofpipe and fill the annular region at the depth of that joint of pipe.Alternatively, the operator may elect to forego perforating casing atthat depth or along a certain zone of interest.

The communications node 400 optionally also includes one or more sensors432. The sensors 432 may be, for example, pressure sensors, temperaturesensors, or microphones. The sensor 432 sends signals to the transceiver440 through a short electrical wire 435 or through the printed circuitboard 435. Signals from the sensor 432 are converted into acousticsignals using an electro-acoustic transducer, that are then sent by thetransceiver 440 as part of the packet of information.

Preferably, the sensor 432 is a temperature sensor. The packet ofinformation will then include signals representative of temperaturereadings taken by the temperature sensor. When the signal reaches thereceiver at the surface, the signal is compared with a baseline value.The baseline value represents an anticipated temperature for a joint ofcasing having a fresh column of cement residing there around. Those ofordinary skill in the art of well completions will understand thatcement mix undergoes an exothermic reaction which causes an increase intemperature.

If the measured temperature value is at or above the baselinetemperature value, then the operator can assume that a cement sheath hasbeen placed around the joint of pipe at issue. On the other hand, if themeasured temperature value is below the baseline temperature value, thenthe operator should assume that a poor cement sheath has been placedaround the joint of pipe at issue. Appropriate remedial steps may thenbe considered.

Additional methods of processing temperature data may be used. Forexample, the receiver may collect temperature data from a designatednumber of communications nodes that are in proximity to the subjectcommunications node. Temperature readings will then be averaged todetermine a moving average temperature value for a section of casing.The measured temperature reading will then be compared to the movingaverage temperature value to determine cement integrity at the level ofa particular joint of pipe.

Ideally, the operator will review a combination of amplitude data andtemperature data along the wellbore to confirm cement sheath integrity.Strain data and passive acoustic data may also be used to evaluate theintegrity of the cement sheath.

The communications node 400 also optionally includes a shoe 500. Morespecifically, the node 400 includes a pair of shoes 500 disposed atopposing ends of the wall 412. Each of the shoes 500 provides a beveledface that helps prevent the node 400 from hanging up on an externaltubular body or the surrounding earth formation, as the case may be,during run-in or pull-out. The shoes 500 may have a protective outerlayer 422 and an optional cushioning material 424 under the outer layer422.

FIGS. 5A and 5B are perspective views of an illustrative shoe 500 as maybe used on an end of the communications node 400 of FIG. 4A, in oneembodiment. In FIG. 5A, the leading edge or front of the shoe 500 isseen, while in FIG. 4B the back of the shoe 500 is seen.

The shoe 500 first includes a body 510. The body 510 includes a flatunder-surface 512 that butts up against opposing ends of the wall 412 ofthe communications node 400.

Extending from the under-surface 512 is a stem 520. The illustrativestem 520 is circular in profile. The stem 520 is dimensioned to bereceived within opposing recesses 414 of the wall 412 of the node 400.

Extending in an opposing direction from the body 510 is a beveledsurface 530. As noted, the beveled surface 530 is designed to preventthe communications node 400 from hanging up on an object during run-ininto a wellbore.

Behind the beveled surface 530 is a flat (or slightly arcuate) surface535. The surface 535 is configured to extend along the drill string 160(or other tubular body) when the communications node 400 is attachedalong the tubular body. In one aspect, the shoe 500 includes an optionalshoulder 515. The shoulder 515 creates a clearance between the flatsurface 535 and the tubular body opposite the stem 520.

In one arrangement, the communications nodes 400 with the shoes 500 arewelded onto an outer surface of the tubular body, such as wall 310 ofthe pipe joint 300. More specifically, the body 410 of the respectivecommunications nodes 400 are welded onto the wall of a joint of casing.In some cases, it may not be feasible or desirable to pre-weld thecommunications nodes 400 onto pipe joints before delivery to a wellsite. Further still, welding may degrade the tubular integrity or damageelectronics in the housing 410. Therefore, it is desirable to utilize aclamping system that allows a drilling or service company tomechanically connect/disconnect the communications nodes 400 along atubular body as the tubular body is being run into a wellbore.

FIG. 6 is a perspective view of a communications node system 600 as maybe used for methods of the present invention, in one embodiment. Thecommunications node system 600 utilizes a pair of clamps 610 formechanically connecting a communications node 400 onto a tubular body630 such as a joint of casing or liner.

The system 600 first includes at least one clamp 610. In the arrangementof FIG. 6, a pair of clamps 610 is used. Each clamp 610 abuts theshoulder 515 of a respective shoe 500. Further, each clamp 610 receivesthe base 535 of a shoe 500. In this arrangement, the base 535 of eachshoe 500 is welded onto an outer surface of the clamp 610. In this way,the clamps 610 and the communications node 400 become an integral tool.

The illustrative clamps 610 of FIG. 6 include two arcuate sections 612,614. The two sections 612, 614 pivot relative to one another by means ofa hinge. Hinges are shown in phantom at 615. In this way, the clamps 610may be selectively opened and closed.

Each clamp 610 also includes a fastening mechanism 620. The fasteningmechanisms 620 may be any means used for mechanically securing a ringonto a tubular body, such as a hook or a threaded connector. In thearrangement of FIG. 6, the fastening mechanism is a threaded bolt 625.The bolt 625 is received through a pair of rings 622, 624. The firstring 622 resides at an end of the first section 612 of the clamp 610,while the second ring 624 resides at an end of the second section 614 ofthe clamp 610. The threaded bolt 625 may be tightened by using, forexample, one or more washers (not shown) and threaded nuts 627.

In operation, a clamp 610 is placed onto the tubular body 630 bypivoting the first 612 and second 614 arcuate sections of the clamp 610into an open position. The first 612 and second 614 sections are thenclosed around the tubular body 630, and the bolt 625 is run through thefirst 622 and second 624 receiving rings. The bolt 625 is then turnedrelative to the nut 627 in order to tighten the clamp 610 and connectedcommunications node 400 onto the outer surface of the tubular body 630.Where two clamps 610 are used, this process is repeated.

The tubular body 630 may be, for example, a casing string such as theillustrative casing string 160 of FIG. 1. Alternatively, the tubularbody 630 may be a string of production tubing such as the tubing 240 ofFIG. 2. In any instance, the wall 412 of the communications node 400 isfabricated from a steel material having a resonant frequency compatiblewith the resonant frequency of the tubular body 630. Stated another way,the mechanical resonance of the wall 412 is at a frequency containedwithin the frequency band used for telemetry.

In one aspect, the communications node 400 is about 12 to 16 inches(0.30 to 0.41 meters) in length as it resides along the tubular body630. Specifically, the housing 410 of the communications node may be 8to 10 inches (0.20 to 0.25 meters) in length, and each opposing shoe 500may be 2 to 5 inches (0.05 to 0.13 meters) in length. Further, thecommunications node 400 may be about 1 inch in width and inch in height.The base 410 of the communications node 400 may have a concave profilethat generally matches the radius of the tubular body 630.

A method for transmitting date in a wellbore is also provided herein.The method preferably employs the communications node 400 and thecommunications node system 600 of FIG. 6.

FIG. 7 provides a flow chart for a method 700 of detecting the integrityof a cement sheath along a wellbore. The method 700 uses a plurality ofdata transmission nodes situated along a casing string to accomplish awireless transmission of data along the wellbore. The data representssignals that indicate the presence of a cement sheath adjacent or inproximity to the respective communications nodes.

The method 700 first includes running a tubular body into the wellbore.This is shown at Box 710. The tubular body is formed by connecting aseries of pipe joints end-to-end, with the pipe joints being connectedby threaded couplings. The joints of pipe are fabricated from a steelmaterial suitable for conducting an acoustic signal.

The method 700 also provides for attaching a series of communicationsnode to the joints of pipe. This is provided at Box 720. Thecommunications nodes are attached according to a pre-designated spacing.In one aspect, each joint of pipe receives a communications node.Preferably, each of the subsurface communications nodes is attached to ajoint of pipe by one or more clamps. In this instance, the step 720 ofattaching the communications nodes to the joints of pipe comprisesclamping the communications nodes to an outer surface of the joints ofpipe. Alternatively, an adhesive material or welding may be used for theattaching step 720.

The method 700 further includes placing a cement sheath around thetubular body. This is indicated at Box 730. The cement sheath is placedwithin an annular region formed between the casing joints and thesurrounding subsurface rock matrix or previous strings of casing. Thecement sheath is placed in the annular region using any known method ofcementing casing into a wellbore. Typically, cement is injected down thecasing string behind a bottom wiper plug and ahead of a top wiper plug,through a cement shoe, and back up the annular region. In the method700, the cement sheath will ideally surround the externally placedcommunications nodes in the annular region along areas where a cementsheath is desired.

The communications nodes include a series of subsurface communicationsnodes. The nodes reside along the casing string. The communicationsnodes also include a topside communications node. This is the uppermostcommunications node along the wellbore. The topside communications nodemay be attached to the tubular body proximate the surface. Morepreferably, the topside communications node is connected to the wellhead. The topside communications node transmits signals from anuppermost subsurface communications node to a receiver at the surface.

The subsurface communications nodes are configured to transmit acousticwaves up to the topside communications node. Each subsurfacecommunications node includes a transceiver that receives an acousticsignal from a previous communications node, and then transmits or relaysthat acoustic signal to a next communications node, in node-to-nodearrangement.

The method 700 also includes providing a receiver. This is shown at Box740. The receiver is placed at the surface. The receiver has a processorthat processes signals received from the topside communications node,such as through the use of firmware and/or software. The receiverpreferably receives electrical or optical signals via a so-called “ClassI, Division I” conduit or through a radio signal. The processorprocesses signals to identify which signals correlate to whichsubsurface communications node. This may involve the use of amultiplexer or a pulse-receive switch.

The method next includes transmitting signals from each of thecommunications nodes up the wellbore and to the receiver. This isprovided at Box 750. The signals are acoustic signals that have aresonance amplitude. These signals are sent up the wellbore,node-to-node. In one aspect, piezo wafers or other piezoelectricelements are used to receive and transmit acoustic signals. In anotheraspect, multiple stacks of piezoelectric crystals or othermagnetostrictive devices are used. Signals are created by applyingelectrical signals of an appropriate frequency across one or morepiezoelectric crystals, causing them to vibrate at a rate correspondingto the frequency of the desired acoustic signal.

In one aspect, the data transmitted between the nodes is represented byacoustic waves according to a multiple frequency shift keying (MFSK)modulation method. Although MFSK is well-suited for this application,its use as an example is not intended to be limiting. It is known thatvarious alternative forms of digital data modulation are available, forexample, frequency shift keying (FSK), multi-frequency signaling (MF),phase shift keying (PSK), pulse position modulation (PPM), and on-offkeying (OOK). In one embodiment, every 4 bits of data are represented byselecting one out of sixteen possible tones for broadcast.

Acoustic telemetry along tubulars is characterized by multi-path orreverberation which persists for a period of milliseconds. As a result,a transmitted tone of a few milliseconds duration determines thedominant received frequency for a time period of additionalmilliseconds. Preferably, the communication nodes determine thetransmitted frequency by receiving or “listening to” the acoustic wavesfor a time period corresponding to the reverberation time, which istypically much longer than the transmission time. The tone durationshould be long enough that the frequency spectrum of the tone burst hasnegligible energy at the frequencies of neighboring tones, and thelistening time must be long enough for the multipath to becomesubstantially reduced in amplitude. In one embodiment, the tone durationis 2 ms, then the transmitter remains silent for 48 milliseconds beforesending the next tone. The receiver, however, listens for 2+48=50 ms todetermine each transmitted frequency, utilizing the long reverberationtime to make the frequency determination more certain. Beneficially, theenergy required to transmit data is reduced by transmitting for a shortperiod of time and exploiting the multi-path to extend the listeningtime during which the transmitted frequency may be detected.

In one embodiment, an MFSK modulation is employed where each tone isselected from an alphabet of 16 tones, so that it represents 4 bits ofinformation. With a listening time of 50 ms, for example, the data rateis 80 bits per second.

The tones are selected to be within a frequency band where the signal isdetectable above ambient and electronic noise at least two nodes awayfrom the transmitter node so that if one node fails, it can be bypassedby transmitting data directly between its nearest neighbors above andbelow. In one example the tones are evenly spaced in period within afrequency band from about 100 kHz to 125 kHz. In another example, thetones are evenly spaced in frequency within a frequency band from about100 kHz to 125 kHz.

Preferably, the nodes employ a “frequency hopping” method where the lasttransmitted tone is not immediately re-used. This prevents extendedreverberation from being mistaken for a second transmitted tone at thesame frequency. For example, 17 tones are utilized for representing datain an MFSK modulation scheme; however, the last-used tone is excluded sothat only 16 tones are actually available for selection at any time.

The communications nodes will transmit data as mechanical waves at arate exceeding about 50 bps.

In one embodiment, each of the subsurface communications nodes alsoincludes a temperature sensor. When the cement job is complete and thecement is setting, an exothermic reaction will take place. Changes intemperature will be indicative of the presence of cement betweencommunications nodes. Later during production, changes in temperaturemay be indicative of the presence of formation fluids flowing behind thecasing string. This may be indicative of flaws in the cement sheath. Inany instance, the communications nodes are then designed to generate asignal that corresponds to temperature readings sensed by the respectivetemperature sensors along their corresponding joints of pipe.

Other sensors may also be employed in selected subsurface communicationsnodes. In one embodiment, strain gauges are used as sensors. Straingauge data can be used to determine changes in stress on the casing ascement transitions from a fluid capable of transmitting hydrostaticpressure to a solid that is set. Strain gauge data can also be used tolater identify volumetric changes within the set cement due to chemicalreactions as cement hydration continues. Further, strain gauge data maybe used to detect a pressure increase in the wellbore due to reservoirfluid influx through a flaw in the cement sheath. Data from the straingauges may be included as part of the packet of information sent to thereceiver at the surface for analysis.

In another embodiment, microphones are placed within selected subsurfacecommunications nodes. Passive acoustic data gathered by microphones canbe used to detect wellbore fluids, especially gas, that are flowingthrough a flaw or a mud channel in the cement sheath. As gas movesthrough a small gap it will produce ambient noises across a broad rangeof frequencies that can be detected by passive acoustic sensors in thenodes. Data from microphones may be included as part of the packet ofinformation sent to the receiver at the surface for analysis.

As can be seen, various data can be gathered by sensors includingtemperature measurements, casing strain, noise caused by gas flow, andacoustic wave measurements themselves. All of this data may beconsidered together in evaluating a cement sheath along a wellbore.

The method 700 also includes analyzing the signals from thecommunications nodes. This is seen at Box 760. The signals are analyzedto evaluate the integrity of the cement sheath adjacent or in proximityto each of the subsurface communications nodes. Preferably, the signalsare analyzed after the cement has set into a solid material having acompressive strength. Analyzing the signals may mean comparing theamplitude to a baseline or to other amplitude readings.

The receiver (or a processor associated with the receiver) will compareamplitude values of the various acoustic signals, or waveforms, againsta baseline amplitude value to confirm that the amplitude is not toohigh. The baseline amplitude value may be a specific value input intothe program representative of an expected amplitude value for a joint ofcasing having fluids within its bore and a cement sheath around itsouter surface. Alternatively, the baseline amplitude value may be amoving average amplitude value determined by the program by averagingamplitude readings from a pre-designated number of communications nodesin proximity to the subject communications node. In one aspect, matrixequations are used to calculate a moving average, which serves as thebaseline amplitude value. In any instance, an excessively high amplitudevalue suggests that cement has not been adequately placed around thepipe proximate to the communications node.

Where the signals correspond to temperature readings, the signals arecompared to a baseline temperature value representing an expectedtemperature for fresh cement. Alternatively, the baseline temperaturevalue may be a moving average temperature value determined by theprogram by averaging temperature readings from a pre-designated numberof communications nodes in proximity to the subject communications node.In any instance, if the temperature reading from a specificcommunications node is too low, this will suggest that cement has notbeen adequately squeezed around the pipe joint at the level of thatcommunications node.

Alternatively, analyzing the signals may mean measuring attenuation of asonic signal. Propagation of acoustic waves between pairs ofelectro-acoustic transducers on neighboring subsurface communicationsnodes produces localized information (between two nodes) about thepresence of cement and bonding. The level of acoustic wave attenuationincreases from empty casing, to water-filled casing, to mud-filledcasing, to casing with cement slurry (before setting), to asolidified/set cement. A plurality of pair-wise acoustic attenuationmeasurements provides a real-time log of the presence of cement.Optionally, this acoustic attenuation data is correlated withconventional cement bond-log data to analyze cement integrity.

A next step in the method 700 may be the identification of a subsurfacecommunications node that is sending signals indicative of poor cementintegrity within the cement sheath. This is provided at Box 770. If itis determined that cement has not been properly placed around the casingstring adjacent one of the communications nodes, various operationaldecisions may be made. This is indicated at Box 780. In some embodiments(not illustrated), Boxes 770 and 780 may be replace with a single boxstating “Make appropriate decision on subsequent drilling, completing,operating, or abandonment of the well.”

In the method 700, each of the communications nodes has an independentpower source. The independent power source may be, for example,batteries or a fuel cell. Having a power source that resided within thehousing of the communications nodes avoids the need for passingelectrical connections through the housing, which could compromise fluidisolation. In addition, each of the intermediate communications nodeshas a transducer and associated transceiver.

Preferably, the electro-acoustic transducer receives acoustic signals ata first frequency, and then sends acoustic signals at a second frequencythat is different from the first frequency. Each transducer then“listens” for signals at the second frequency. Preferably, eachtransducer “listens” for the acoustic waves sent at the first frequencyuntil after reverberation of the acoustic waves at the first frequencyhas substantially attenuated. Thus, a time is selected for bothtransmitting and for receiving. In one aspect, the listening time may beabout twice the time at which the waves at the first frequency aretransmitted or pulsed. To accomplish this, the transducer will operatewith and under the control of a micro-processor located on a printedcircuit board, along with memory. Beneficially, the energy required totransmit signals is reduced by transmitting for a shorter period oftime.

It is noted that the method 700 and the claims herein do not requirethat communications nodes be placed along the entire wellbore, but onlyalong a selected section or sections. Further, the method 700 and theclaims herein do not require that the cement sheath be placed along theentire annular region unless the claims expressly so state.

A separate method for determining the integrity of a cement sheath isprovided herein. The cement sheath resides within an annular regionalong a wellbore. Preferably, the annular region is between a string ofcasing and a surrounding subsurface rock matrix.

The method first includes receiving signals from a wellbore. Each signaldefines a packet of information having (i) an identifier for asubsurface communications node originally transmitting the signal, and(ii) an acoustic amplitude value for the subsurface communications nodeoriginally transmitting the signal.

The method also includes correlating communications nodes to theirrespective locations in the wellbore. In addition, the method comprisesanalyzing the amplitude values to determine whether any of suchamplitude values are indicative of a poor cement sheath along thewellbore.

In this method, the subsurface communications nodes may be constructedin accordance with communications node 350 of FIG. 3, communicationsnode 400 of FIG. 4, or other arrangement for acoustic transmission ofdata. Preferably, each of the subsurface communications nodes isattached to an outer wall of the casing string according to apre-designated spacing, and resides within the annular region. Thesubsurface communications nodes are configured to communicate byacoustic signals transmitted through the casing string.

In one aspect, analyzing the amplitude values comprises identifyingamplitude values generated by each of the subsurface communicationsnodes, and comparing those amplitude values to a baseline amplitudevalue. The baseline amplitude value may be, for example, (i) apreviously stored amplitude value indicative of an amplitude value of ajoint of casing having a continuous annular cement sheath, or (ii) amoving average of amplitude readings taken from a pre-designated numberof communications nodes in proximity to a subject communications node.

In one aspect, each of the subsurface communications nodes furthercomprises a temperature sensor. The communications nodes are thendesigned to generate a signal that corresponds to temperature readingstaken by the temperature sensors. The electro-acoustic transceivers inthe subsurface communications nodes transmit acoustic signals up thewellbore representative of the temperature readings, node-to-node. Inthis instance, the packet of information generated by each subsurfacecommunications node further has (iii) an acoustic waveform indicative ofa temperature reading. In addition, the method further comprisesanalyzing the temperature readings to determine the presence of cementadjacent to the sensor.

In one aspect, analyzing the temperature readings comprises identifyingtemperature values generated by each of the subsurface communicationsnodes, and comparing those temperature values to a baseline temperaturevalue. The baseline temperature value may be (i) a previously storedtemperature value indicative of a temperature value of a joint of casinghaving a freshly-cemented annular region, or (ii) a moving average oftemperature readings taken from a pre-designated number ofcommunications nodes in proximity to a subject communications node inthe wellbore.

As noted above, other sensors may be placed in selected subsurfacecommunications nodes. These may include strain gauges and microphones.

As can be seen, a novel downhole telemetry system is provided, as wellas a novel method for the wireless transmission of information using aplurality of data transmission nodes for detecting cement sheathintegrity. In some States, new hydraulic fracturing regulations arebeing implemented which may require the use of cement bond logs.However, the system disclosed herein may potentially be used by anoperator in lieu a cement bond log.

While it will be apparent that the inventions herein described are wellcalculated to achieve the benefits and advantages set forth above, itwill be appreciated that the inventions are susceptible to modification,variation and change without departing from the spirit thereof.

What is claimed is:
 1. An electro-acoustic telemetry system forevaluating a cement sheath in a wellbore, comprising: a casing stringdisposed in a wellbore, with a cement sheath residing within an annularregion formed between the casing string and a surrounding subsurfacerock matrix along the casing string; a topside communications nodeplaced proximate a surface of the wellbore; a plurality of subsurfacecommunications nodes spaced along the wellbore and attached to an outerwall of the casing string, the subsurface communications nodesconfigured to transmit acoustic waves from node-to-node up the wellboreand to the topside communications node, and with at least some of thesubsurface communications nodes being in contact with the cement sheath;and a receiver at the surface configured to receive signals from thetopside communications node; wherein each of the subsurfacecommunications nodes comprises: a sealed housing; an electro-acoustictransducer and associated transceiver also residing within the housing,with the transceiver being designed to relay signals from node-to-nodeup the wellbore, with each signal representing a packet of informationthat comprises an identifier for the subsurface communications node thatoriginally transmitted the signal, and an acoustic waveform having anamplitude; and an independent power source residing within the housingproviding power to the transceiver.
 2. The electro-acoustic telemetrysystem of claim 1, wherein the subsurface communications nodes arespaced apart such that each joint of pipe supports at least onesubsurface communications node.
 3. The electro-acoustic telemetry systemof claim 1, wherein the subsurface communications nodes are spaced atabout 20 to 40 foot (6.1 to 12.2 meter) intervals.
 4. Theelectro-acoustic telemetry system of claim 1, wherein the subsurfacecommunications nodes transmit data in acoustic form at a rate exceedingabout 50 bps.
 5. The electro-acoustic telemetry system of claim 1,wherein each of the electro-acoustic transceivers is designed to receiveacoustic waves at a first frequency, and then transmit the acousticwaves at a second different frequency up the wellbore to a nextsubsurface communications node.
 6. The electro-acoustic system of claim1, further comprising: one or more sensors placed along the wellbore,the sensors being any of strain gauges, temperature sensors,microphones, or combinations thereof; and wherein the subsurfacecommunications nodes are configured to receive and relay acousticsignals indicative of readings taken by the sensors up to the surface.7. The electro-acoustic system of claim 6, wherein: the one or moresensors reside within the housings of selected subsurface communicationsnodes; and the electro-acoustic transducers within the selectedsubsurface communications nodes convert signals from the sensors intoacoustic signals for the associated transceivers.
 8. Theelectro-acoustic system of claim 6, wherein a frequency band for theacoustic wave transmission by the transceivers is about 25 KHz wide. 9.The electro-acoustic system of claim 6, wherein a frequency band for theacoustic wave transmission by the transceivers operates from about 100kHz to 125 kHz.
 10. The electro-acoustic telemetry system of claim 6,wherein the acoustic waves provide data that is modulated by (i) amultiple frequency shift keying method, (ii) a frequency shift keyingmethod, (iii) a multi-frequency signaling method, (iv) a phase shiftkeying method, (v) a pulse position modulation method, or (vi) an on-offkeying method.
 11. The electro-acoustic telemetry system of claim 6,wherein each subsurface communications node listens for the acousticwaves generated at the first frequency for a longer time than the timefor which the acoustic waves were generated at the second frequency by aprevious subsurface communications node.
 12. The electro-acoustictelemetry system of claim 1, wherein: a well head is placed above thewellbore; and the topside communications node is placed (i) on an outersurface of the well head, (ii) on an outer surface of a tubular bodythat is downstream of the wellhead, or (iii) on the outer surface of anuppermost joint of the casing string.
 13. The electro-acoustic telemetrysystem of claim 12, wherein the signal from the topside communicationsnode to the receiver is transmitted via a Class I, Division I conduit ora wireless transmission.
 14. The electro-acoustic telemetry system ofclaim 1, wherein the subsurface communications nodes are attached to theouter wall of the casing string by (i) an adhesive material, (ii)welding, or (iii) one or more mechanical fasteners.
 15. Theelectro-acoustic telemetry system of claim 1, wherein: each of thesubsurface communications nodes is attached to the casing string by oneor more clamps; and each of the one or more clamps comprises: a firstarcuate section; a second arcuate section; a hinge for pivotallyconnecting the first and second arcuate sections; and a fasteningmechanism for securing the first and second arcuate sections around anouter surface of the casing string.
 16. The electro-acoustic telemetrysystem of claim 1, wherein: the receiver comprises a processor; and theprocessor is programmed to identify amplitude values generated by eachsubsurface communications node and compare those amplitude values to abaseline amplitude value.
 17. The electro-acoustic telemetry system ofclaim 16, wherein the baseline amplitude value is (i) a previouslystored amplitude value indicative of an amplitude value of a joint ofcasing having a continuous annular cement sheath, or (ii) a movingaverage of amplitude readings taken from a pre-designated number ofcommunications nodes in proximity to a subject communications node. 18.The electro-acoustic telemetry system of claim 16, wherein: selectedcommunications nodes further comprise a temperature sensor, with thoseselected communications nodes being designed to generate a signal thatcorresponds to temperature readings taken by the respective temperaturesensors; and the transceivers transmit acoustic signals up the wellborerepresentative of the temperature readings, node-to-node, as part of thepackets of information.
 19. The electro-acoustic telemetry system ofclaim 18, wherein the processor is further programmed to identifytemperature values generated by the selected subsurface communicationsnode and compare those temperature values to a baseline temperaturevalue.
 20. The electro-acoustic telemetry system of claim 19, whereinthe baseline temperature value is (i) a previously stored temperaturevalue indicative of a temperature value of a joint of casing having afreshly-cemented annular region, or (ii) is a moving average oftemperature readings taken from a pre-designated number ofcommunications nodes in proximity to a subject communications node. 21.The electro-acoustic telemetry system of claim 16, wherein: selectedcommunications nodes further comprise a strain gauge, with thoseselected communications nodes being designed to generate a signal thatcorresponds to strain readings taken by the respective strain gauges;and the electro-acoustic transceivers transmit acoustic signals up thewellbore representative of the strain readings, node-to-node, as part ofthe packets of information.
 22. The electro-acoustic telemetry system ofclaim 16, wherein: selected communications nodes further comprise apassive acoustic sensor, with those selected communications nodes beingdesigned to generate a signal that corresponds to ambient noise readingstaken by the respective temperature sensors; and the electro-acoustictransceivers transmit acoustic signals up the wellbore representative ofthe noise readings, node-to-node, as part of the packets of information.23. A method of detecting the integrity of a cement sheath along awellbore, comprising: running joints of casing into the wellbore, thejoints of casing being connected by threaded couplings to form a casingstring; attaching a series of communications nodes to the joints ofcasing according to a pre-designated spacing, wherein adjacentcommunications nodes are configured to communicate by acoustic signalstransmitted through the joints of casing, and wherein each of thecommunications nodes comprises: a sealed housing; an electro-acoustictransducer and associated transceiver residing within the housingconfigured to relay signals, with each signal representing a packet ofinformation that comprises an identifier for the subsurfacecommunications node originally transmitting the signal, and an acousticwaveform; and an independent power source also residing within thehousing for providing power to the transceiver; placing a cement sheathwithin an annular region formed between the casing string and asurrounding subsurface matrix substantially along the wellbore; sendingsignals from the communications nodes to a receiver at a surface via theseries of communications nodes; and analyzing the signals to evaluatethe integrity of the cement sheath proximate each of the communicationsnodes.
 24. The method of claim 23, wherein the surface is an earthsurface, or a drilling or production platform over a water surface. 25.The method of claim 20, wherein the housing for each of the intermediatecommunications nodes is fabricated from a steel material, with the steelmaterial of the housing having a resonance frequency within a width ofthe resonance frequency of the acoustic waveforms transmitted throughthe joints of casing.
 26. The method of claim 23, wherein: the series ofcommunications nodes comprises a topside communications node residingproximate the surface, and a series of subsurface communications nodesalong the wellbore below the topside communications nodes; and thetopside communications node transmits the signals from an uppermostsubsurface communications node to the receiver.
 27. The method of claim26, wherein: a well head is placed above the wellbore; and the topsidecommunications node is clamped (i) on an outer surface of the well head,or (ii) on the outer surface of an uppermost joint of the casing string.28. The method of claim 27, wherein the topside communications node isin electrical communication with the receiver by means of a Class I,Division I conduit or a wireless transmission.
 29. The method of claim26, wherein each of the subsurface communications nodes is attached toan outer wall of a joint of casing by (i) an adhesive material, (ii)welding, or (iii) one or more mechanical fasteners.
 30. The method ofclaim 26, wherein: each of the subsurface communications nodes isattached to a joint of casing by one or more clamps; and the step ofattaching the communications nodes to the joints of casing comprisesclamping the communications nodes to an outer surface of the joints ofcasing.
 31. The method of claim 30, wherein: the housing of each of thesubsurface communications nodes comprises a first end and a secondopposite end; and each of the one or more clamps comprises a first clampsecured at the first end of the housing, and a second clamp secured atthe second end of the housing.
 32. The method of claim 23, wherein thesubsurface communications nodes are spaced apart such that each joint ofcasing supports at least one subsurface communications node.
 33. Themethod of claim 23, wherein the subsurface communications nodes arespaced at about 20 to 40 foot (6.1 to 12.2 meter) intervals.
 34. Themethod of claim 23, wherein the subsurface communications nodes transmitdata representing the waveforms at a rate exceeding about 50 bps. 35.The method of claim 23, wherein analyzing the signals to evaluate theintegrity of the cement sheath comprises: identifying amplitude valuesgenerated by each of the subsurface communications nodes; and comparingthose amplitude values to a baseline amplitude value.
 36. The method ofclaim 35, wherein the baseline amplitude value is (i) a previouslystored amplitude value indicative of an amplitude value of a joint ofcasing having a continuous annular cement sheath, or (ii) a movingaverage of amplitude readings taken from a pre-designated number ofcommunications nodes in proximity to a subject communications node. 37.The method of claim 36, wherein: each of the subsurface communicationsnodes further comprises a temperature sensor, and is designed togenerate a signal that corresponds to temperature readings taken by thetemperature sensor; and the electro-acoustic transceivers in thesubsurface communications nodes also transmit acoustic signals up thewellbore representative of the temperature readings, node-to-node. 38.The method of claim 35, wherein analyzing the signals to determine theintegrity of the cement sheath further comprises: identifyingtemperature values generated by each of the subsurface communicationsnodes; and comparing those temperature values to a baseline temperaturevalue.
 39. The method of claim 38, wherein the baseline temperaturevalue is (i) a previously stored temperature value indicative of atemperature value of a joint of casing having a freshly-cemented annularregion, or (ii) a moving average of temperature readings taken from apre-designated number of communications nodes in proximity to a subjectcommunications node in the wellbore.
 40. The method of claim 23,wherein: selected communications nodes further comprise a strain gauge,with those selected communications nodes being designed to generate asignal that corresponds to strain readings taken by the respectivestrain gauges; and the electro-acoustic transceivers transmit acousticsignals up the wellbore representative of the strain readings,node-to-node, as part of the packets of information.
 41. The method ofclaim 23, wherein: selected communications nodes further comprise apassive acoustic sensor, with those selected communications nodes beingdesigned to generate a signal that corresponds to ambient noise readingstaken by the respective temperature sensors; and the electro-acoustictransceivers transmit acoustic signals up the wellbore representative ofthe noise readings, node-to-node, as part of the packets of information.42. The method of claim 23, wherein a frequency band for the acousticwave transmission by the transceivers is about 25 KHz wide.
 43. Themethod of claim 23, wherein a frequency band for the acoustic wavetransmission by the transceivers operates from about 100 kHz to 125 kHz.44. The method of claim 23, wherein the acoustic waves provide data thatis modulated by (i) a multiple frequency shift keying method, (ii) afrequency shift keying method, (iii) a multi-frequency signaling method,(iv) a phase shift keying method, (v) a pulse position modulationmethod, or (vi) an on-off keying method.
 45. The method of claim 23,further comprising: identifying a subsurface communications node sendingsignals indicative of poor cement integrity within the surroundingcement sheath.
 46. The method of claim 23, further comprising:perforating the joint of casing supporting that subsurfacecommunications node; and squeezing cement through the perforated jointof casing and into the annular region around the casing string.
 47. Themethod of claim 23, wherein analyzing the signals to evaluate theintegrity of the cement sheath further comprises comparing theattenuation of acoustic signals between pairs of subsurfacecommunications nodes.
 48. The method of claim 47, wherein analyzing thesignals to evaluate the integrity of the cement sheath further comprisescomparing the attenuation of acoustic signals with cement bond-log data.49. A method of detecting the integrity of a cement sheath in an annularregion along a wellbore, comprising: receiving signals from a wellbore,each signal defining a packet of information having (i) an identifierfor a subsurface communications node originally transmitting the signal,and (ii) an acoustic amplitude value for the subsurface communicationsnode originally transmitting the signal; correlating subsurfacecommunications nodes to their respective locations in the wellbore; andanalyzing the amplitude values to determine whether any of suchamplitude values are indicative of a poor cement sheath along thewellbore.
 50. The method of claim 49, wherein: the annular regionresides between a casing string and a surrounding subsurface rockmatrix; and each of the subsurface communications nodes is attached toan outer wall of the casing string according to a pre-designatedspacing, and resides within the annular region.
 51. The method of claim50, wherein: the subsurface communications nodes are configured tocommunicate by acoustic signals transmitted through the casing string,and each of the communications nodes comprises: a sealed housing; anelectro-acoustic transducer and associated transceiver residing withinthe housing; and an independent power source also residing within thehousing for providing power to the transceiver.
 52. The method of claim51, wherein analyzing the amplitude values comprises: identifyingamplitude values generated by each of the subsurface communicationsnodes; and comparing those amplitude values to a baseline amplitudevalue.
 53. The method of claim 52, wherein the baseline amplitude valueis (i) a previously stored amplitude value indicative of an amplitudevalue of a joint of casing having a continuous annular cement sheath, or(ii) a moving average of amplitude readings taken from a pre-designatednumber of communications nodes in proximity to a subject communicationsnode.
 54. The method of claim 52, wherein: selected subsurfacecommunications nodes further comprises a temperature sensor, and aredesigned to generate a signal that corresponds to temperature readingstaken by the temperature sensor; the electro-acoustic transceivers inthe subsurface communications nodes transmit acoustic signals up thewellbore representative of the temperature readings, node-to-node; thepacket of information generated by each subsurface communications nodefurther has (iii) an acoustic waveform indicative of a temperaturereading; and the method further comprises analyzing the temperaturereadings to determine whether any of such temperature readings areindicative of a poor cement sheath along the wellbore.
 55. The method ofclaim 54, wherein analyzing the temperature readings comprises:identifying temperature values generated by each of the subsurfacecommunications nodes; and comparing those temperature values to abaseline temperature value.
 56. The method of claim 55, wherein thebaseline temperature value is (i) a previously stored temperature valueindicative of a temperature value of a joint of casing having afreshly-cemented annular region, or (ii) a moving average of temperaturereadings taken from a pre-designated number of communications nodes inproximity to a subject communications node in the wellbore.
 57. Themethod of claim 52, wherein: at least some of the subsurfacecommunications nodes further comprises a passive acoustic sensor, andgenerate a signal that corresponds to ambient noise readings taken bythe passive acoustic sensors; the electro-acoustic transceivers in thesubsurface communications nodes transmit acoustic signals up thewellbore representative of the ambient noise readings, node-to-node; thepacket of information generated by the subsurface communications nodesfurther has (iii) an acoustic waveform indicative of the ambient noisereadings; and the method further comprises analyzing the ambient noisereadings to determine whether any of such ambient noise readings areindicative of a poor cement sheath along the wellbore.
 58. The method ofclaim 52, wherein: at least some of the subsurface communications nodesfurther comprises a strain gauge, and generate a signal that correspondsto strain readings taken by the strain gauges; the electro-acoustictransceivers in the subsurface communications nodes transmit acousticsignals up the wellbore representative of the strain readings,node-to-node; the packet of information generated by the subsurfacecommunications nodes further has (iii) an acoustic waveform indicativeof the strain readings; and the method further comprises analyzing thestrain readings to determine whether any of such strain readings areindicative of a poor cement sheath along the wellbore.